Reservoir fluid properties data are very important in reservoir engineering computations such as material balance calculations, well testing, reserve estimates, and numerical reservoir simulations. Ideally, those data should be obtained experimentally. On some occasions, these data are not available or reliable; then, empirically derived correlations are used to predict PVT properties. However, ... [Show full abstract] the success of such correlations in predicting the properties depends mainly on the range of data with which they were originally developed. A review of the frequently used correlations, along with the statistical accuracy of these correlations when compared to Nigerian data, is the focus of this paper.
More than 2500 unpublished PVT data sets from different locations in Nigeria were acquired for the evaluation of the most frequently used pressure-volume-temperature (PVT) empirical correlation for Nigeria data crude oil samples. The best available correlations were selected by comparison with a large database of reservoir-fluid studies of samples collected from different locations in Nigeria. The comparison is based on statistical error analysis. This paper gives the best correlations for field applications for estimating bubblepoint pressure, solution gas-oil ratio and oil formation volume factor at bubble point pressure.
The results of this study show that the present practice of arbitrarily choosing any correlations for bubblepoint pressure (Pb), Solution gas-oil ratio (Rs) and formation volume factor at bubblepoint (Bob) estimation is not the optimum.